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PUBLIC NOTICE U.S. Environmental Protection Agency
Region 4 Water Protection Division
National Pollution Discharge Elimination System Permitting &
Enforcement Branch Atlanta Federal Center 61 Forsyth Street, S.W.
Atlanta, Georgia 30303
(404) 562-9731
Public Notice No. 16AL00001 Date: August 18, 2016
NOTICE OF PROPOSED REISSUANCE OF NATIONAL POLLUTANT DISCHARGE
ELIMINATION SYSTEM PERMIT
The United States Environmental Protection Agency (EPA) Region 4
intends to reissue the National Pollutant Discharge Elimination
System (NPDES) general permit for the Outer Continental Shelf (OCS)
of the Gulf of Mexico (General Permit No. GEG460000) for discharges
in the Offshore Subcategory of the Oil and Gas Extraction Point
Source Category [40 Code of Federal Regulations (CFR) Part 435,
subpart A].
The existing permit, issued by EPA Region 4 on March 15, 2010,
and became effective on April 1, 2010, authorized discharges from
exploration, development, and production facilities located in and
discharging to all Federal waters of the eastern portion of the
Gulf of Mexico seaward of the outer boundary of the territorial
seas. The permit expired on March 31, 2015, and has been
administratively continued.
The proposed reissuance of this NPDES permit covers existing and
new source facilities located on Federal leases occurring in water
depths seaward of 200 meters, occurring offshore the coasts of
Alabama and Florida. The western boundary of the coverage area is
demarcated by Mobile and Visoca Knoll lease blocks located seaward
of the outer boundary of the territorial seas from the coasts of
Mississippi and Alabama.
The proposed NPDES permit establishes limitations on the amounts
of pollutants allowed to be discharged and was drafted in
accordance with the provisions of the Clean Water Act (33 U.S.C.
Section 1251, et seq.) (Act) and other lawful standards and
regulations. The proposed permit is tentative and open to comment
from the public. Specifically, the proposed NPDES general permit
includes, best conventional pollutant control technology (BCT), and
best available technology economically achievable (BAT) limitations
for existing sources and new source performance standards (NSPS)
limitations for new sources as promulgated in the effluent
guidelines for the offshore subcategory at 58 FR 12454 and amended
at 66 FR 6850 (March 4, 1993 and January 22, 2001,
respectively).
Three companion documents were prepared for the proposed general
permit. The Environmental Assessment (EA) and preliminary Finding
of No Significant Impact (FNSI) were prepared in accordance with
the National Environmental Policy Act and consider revisions to the
general permit for wastewater discharges from oil and gas
extraction activities within Region 4 jurisdiction of the offshore
continental shelf off of Mississippi, Alabama and Florida. The EA
supplements a 2004 Supplemental
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Environmental Impact Statement prepared for the general permit
issued that year. The Ocean Discharge Criteria Evaluation Document
(Clean Water Act Section 403 Determination) is a technical support
document which specifically addresses ten factors for determining
unreasonable degradation in the coverage area.
A Federal Register notice announcing the availability of the
proposed permit, permit fact sheet, EA, preliminary FNSI and Ocean
Discharge Criteria Evaluation Document (CWA Section 403
Determination) is scheduled to be published in the Federal Register
on August 18, 2016, which will also commence the beginning of the
public comment period for these documents. The public comment
period will end on September 17, 2016, or 30 days from the
publication date of this notice, whichever is later.
Persons wishing to comment upon or object to any aspects of a
draft permit are invited to submit same in writing to the, Water
Protection Division, U.S. Environmental Protection Agency, Atlanta
Federal Center, NPDES Permits Section, 61 Forsyth Street, S.W.,
Atlanta, Georgia 30303, ATTENTION: Ms. Bridget Staples, NPDES
Offshore Oil and Gas Coordinator. Comments may also be send via
email to: [email protected]. Pursuant to 40 CFR 124.13, any
person who believes that any permit condition is inappropriate must
raise all reasonably ascertainable issues and submit all reasonably
available arguments in full, supporting his or her position, by the
close of the comment period. The public notice number and NPDES
permit number should be included in the first page of comments.
All comments received within the public comment period will be
considered in the formulation of a final determination regarding
the proposed permit.
After consideration of all written comments and the requirements
and polices in the Act and appropriate regulations, the EPA
Regional Administrator will make a determination regarding the
permit issuance. If the determination is substantially unchanged
from that announced by this notice, the EPA Regional Administrator
will so notify all persons submitting written comments. If the
determination is substantially unchanged, the EPA Regional
Administrator will issue a public notice indicating the revised
determination. Request(s) for an evidentiary hearing may be filed
after the Regional Administrator makes the above-described
determination. No issues shall be raised by any party that were not
submitted to the administrative record as part of the preparation
of and comment on the draft permit, unless good cause is shown for
the failure to submit them in accordance with 40 CFR 124.76.
Additional information regarding an evidentiary hearing is
available in 40 CFR 124, Subpart E, or by contacting the Office of
General Counsel at the address above or at (404) 562- 9525.
The administrative record, including the proposed permit, fact
sheet, EA, preliminary FNSI and Ocean Discharge Criteria Evaluation
document, a sketch showing the exact location of the permit area,
comments received, and additional information on hearing procedures
is available at cost by writing to the EPA at the address above,
for review and copying at Atlanta Federal Center, 61 Forsyth
Street, S.W. Atlanta, Georgia, between the hours of 8:15 a.m. and
4:30 p.m., Monday through Friday (copies will be provided at a
minimal cost per page), or by downloading these documents from
http://www.epa.gov/aboutepa/about-epa-region-4-southeast.
Please bring the foregoing to the attention of persons whom you
know will be interested in this matter. If you would like to be
added to our public notice mailing list, submit your name and
mailing address to the EPA, at the address given above.
mailto:[email protected]://www.epa.gov/aboutepa/about-epa-region-4-southeast
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Draft National Pollutant Discharge Elimination System (NPDES)
General Permit No. GEG460000 For Offshore Oil and Gas Activities in
the Eastern Gulf of Mexico
TABLE OF CONTENTS
Part I. Requirements for NPDES Permits A. Permit Applicability
and Coverage Conditions
1. Operations Covered 2. Types of Operators and Operations
Excluded 3. General Permit Applicability 4. Notification
Requirements (Existing and New Sources) 5. Operational Facilities
6. Non-Operational Facilities 7. Termination of Operations 8.
Intent to be Covered by a Subsequently Issued Permit 9. Transfer of
General Permit Coverage
B. Effluent Limitations and Monitoring Requirements
1. Drilling Fluids 2. Drill Cuttings 3. Produced Water 4. Deck
Drainage 5. Produced Sand 6. Well Treatment Fluids, Completion
Fluids, and Workover Fluids 7. Sanitary Waste (Facilities
Continuously Manned by 10 or More Persons) 8. Sanitary Waste
(Facilities Continuously Manned by 9 or Fewer Persons or
Intermittently by Any Number) 9. Domestic Waste
10. Miscellaneous Discharges 11. Miscellaneous Discharges of
Freshwater and Seawater in Which Chemicals Have Been Added C. Other
Discharge Conditions
1. Floating Solids or Visible Foam 2. Halogenated Phenol
Compounds 3. Dispersants, Surfactants, and Detergents 4. Rubbish,
Trash, and Other Refuse 5. Dual Gradient Drilling Discharges 6.
Un-used Chemicals or Products
D. Special Conditions
1. De minimus Discharges 2. Small Volume Discharges 3. Cooling
Water Intake Structure 4. Reference Drilling Fluid Formulation 5.
Preparation of Live-Bottom Survey and Live Bottom Reports Using
High
Resolution Acoustical Data
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Part II. Standard Conditions for NPDES Permits A. General
Conditions
1. Duty to Comply 2. Penalties for Violations of Permit
Conditions 3. Civil and Criminal Liability 4. Duty to Mitigate 5.
Permit Actions 6. Toxic Pollutants 7. Oil and Hazardous Substance
Liability 8. State Laws 9. Effect of a Permit
10. Property Rights 11. Onshore or Offshore Construction 12.
Severability 13. Duty to Provide Information B. Proper Operation
and Maintenance of Pollution Controls
1. Proper Operation and Maintenance 2. Need to Halt or Reduce
not a Defense 3. Bypass of Treatment Facilities 4. Upsets 5.
Removed Substances
C. Monitoring and Records
1. Representative Sampling 2. Flow Measurements 3. Monitoring
Procedures 4. Penalties for Tampering 5. Retention of Records 6.
Record Contents 7. Inspection and Entry
D. Reporting Requirements
1. Change in Discharge 2. Anticipated Noncompliance 3. Transfer
of Ownership 4. Monitoring Reports 5. Additional Monitoring by the
Permittee 6. Averaging of Measurements 7. Compliance Schedules 8.
Twenty-four Hour Reporting 9. Other Noncompliance
10. Changes in Discharge of Toxic Substances 11. Duty to Reapply
12. Signatory Requirements 13. Availability of Reports 14.
Penalties for Falsification of Reports E. Definitions
1. Permit Issuing Authority
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2. Act 3. Mass/Day Measurements 4. Concentration Measurements 5.
Other Measurements 6. Types of Samples 7. Calculation of Means 8.
Calendar Day 9. Hazardous Substance
10. Toxic Pollutants Part III. Monitoring Reports and Permit
Modification A. Monitoring Reports B. Permit Modification Part IV.
Best Management Practices/Pollution Prevention Plan (BMP3) A.
Objective B. General Requirements C. Part IV Definitions D.
Specific BMP3 Plan Requirements E. Signatory Authority and
Management Responsibilities F. Plan Certification G. Plan
Documentation H. Best Management Practices and Pollution Prevention
Committee I. Employee Training J. Plan Development and
Implementation K. Plan Review L. Plan Modification Part V. Test
Procedures and Definitions A. Test Procedures 1. Samples of Wastes
2. Drilling Fluids Toxicity Test (Suspended Particulate Phase
Toxicity Test) 3. Static Sheen Test 4. Visual Sheen Test 5.
Produced Water Toxicity Tests 6. Base Fluid Sediment Toxicity Test
7. Base Fluids Biodegradation Rate 8. Polynuclear Aromatic
Hydrocarbons 9. Formation Oil 10. Drilling Fluids Sediment Toxicity
Test 11. Retention of Non-Aqueous Based Drilling Fluid on Cuttings
12. Sampling Protocol for Stock Sediment Toxicity Test, Drilling
Fluid Sediment Toxicity Test and Biodegradation Test 13. Rounding
of Ratios (To Be Applied in Measuring Compliance with the Sediment
Toxicity and Biodegradation Tests) 14. Modified ISO Test Method
11734: Protocol for the Determination of Degradation of Non-Aqueous
Base Fluids in a Marine Closed Bottle Biodegradation Test System
15. Whole Effluent Toxicity Testing
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B. Other Definitions Table 1: Effluent Limitations,
Prohibitions, and Monitoring Requirements for the Eastern Gulf of
Mexico NPDES General Permit (Existing and New Sources) Table 2:
Effluent Limitations, Prohibitions, and Monitoring Requirements for
the Eastern Gulf of Mexico NPDES General Permit (Existing and New
Sources using Synthetic-Based Drilling Fluids) Appendix A Table 1:
CORMIX Ambient Input Parameters and Constant Input Parameters Table
2: Produced Water Discharge Pipe Diameters Table 3.A: Produced
Water Critical Dilutions (% Effluent) for Water Depth Differences
Between the Discharge Pipe and Sea Floor of Less than 200 Meters
Table 3: CORMIX Predicted Critical Dilutions (Percent Effluent) for
Discharges with a Depth Difference Between the Discharge Pipe
Outlet and the Sea Floor of Greater than 12 Meters and in Waters
Less than 200 Meters Table 4: CORMIX Predicted Critical Dilutions
(Percent Effluent) for Discharges with a Depth Difference Between
the Discharge Pipe Outlet and the Sea Floor of Greater than 12
Meters and in Waters Equal to or Greater than 200 Meters Table 5:
Minimum Vertical Port Separation to Avoid Interference Table 6:
Critical Dilution (% Effluent) for Toxicity Limitations for
Seawater to Which Treatment Chemicals Have Been Added Table 7:
Critical Dilution (% Effluent) for Toxicity Limitations for
Freshwater to Which Treatment Chemicals Have Been Added Appendix B:
Map Identifying Areas of Biological Concern
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ENVIRONMENTAL PROTECTION AGENCY
NOTICE OF DRAFT NPDES GENERAL PERMIT
Draft NPDES General Permit for New and Existing Sources in the
Offshore Subcategory of
the Oil and Gas Extraction Category for the Eastern Portion of
the Outer Continental
Shelf of the Gulf of Mexico (GEG460000)
SUMMARY: Today, the EPA Region 4 is proposing to re-issue the
National Pollutant
Discharge Elimination System (NPDES) general permit for the
eastern portion of the Outer
Continental Shelf (OCS) of the Gulf of Mexico (Permit No.
GEG460000) for discharges from
new sources, existing sources, and new dischargers, in the
Offshore Subcategory of the Oil and
Gas Extraction Point Source Category (40 Code of Federal
Regulations (C.F.R.) Part 435,
Subpart A). When issued, this proposed general permit will
replace the previous permit issued
on March 15, 2010, which became effective on April 1, 2010, and
expired on March 31, 2015.
The general permit authorizes discharges from oil and gas
facilities and supporting pipeline
facilities, engaged in exploration, development, and production
operations located in and
discharging to Federal waters of the Gulf of Mexico seaward of
200 meters depth contour
offshore Alabama and Florida and seaward of the outer boundary
of the territorial seas for
offshore Mississippi and Alabama in Mobile and Viosca Knoll
lease blocks. The term of the
permit will be no longer than five years from the effective date
of the permit.
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FOR FURTHER INFORMATION CONTACT: Mrs. Bridget Staples, EPA
Region 4, Water
Protection Division, 61 Forsyth Street, Atlanta, Georgia 30303,
Telephone: (404) 562- 9783, or
via email to the following address: [email protected].
Authorization To Discharge Under the National Pollutant
Discharge Elimination System
In compliance with the Federal Water Pollution Control Act, as
amended (33 U.S.C. 1251 et.
seq.), operators of new and existing sources and new discharges
from offshore oil and gas
development, production, and exploration facilities in lease
blocks located in Outer Continental
Shelf (OCS) Federal waters in the eastern portion of the Gulf of
Mexico seaward of 200 meters
depth contour offshore Alabama and Florida and in parts of the
Mobile and Viosca Knoll lease
block offshore Mississippi and Alabama, are authorized to
discharge to receiving waters in
accordance with effluent limitations, monitoring requirements,
and other conditions set forth in
Parts I, II, III, IV and V, and appendices thereof.
Operators of facilities within the NPDES general permit coverage
area must submit a Notice
of Intent (NOI) to the Regional Administrator, prior to
discharge, that they intend to be covered
by the general permit (See Part I.A.3). The effective date of
coverage will be the postmarked
date of the NOI, or if the postmarked date is illegible, the
effective date of coverage will be two
days prior to the receipt date of the NOI.
This permit shall become effective at midnight, Eastern Standard
Time, and the permit shall
expire five years from the effective date of the permit.
Administratively continued coverage under the previous NPDES
general permit will cease for
operators 30 days after the effective date of this permit.
Therefore, such operators must submit a
new NOI to be covered under this general permit within 30 days
after the effective date of this
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permit. If a permit application for an individual permit is
filed, the coverage under the previous
general permit terminates when a final action is taken on the
application for an individual permit.
This permit and the authorization to discharge shall expire at
midnight, Eastern Standard
Time on _____________________.
Signed this day of _________________.
James D. Giattina Director Water Protection Division U.S. EPA
Region 4
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Part I. Requirements for NPDES Permits
A. Permit Applicability and Coverage Conditions
1. Operations Covered
This permit establishes effluent limitations, prohibitions,
reporting requirements and other
conditions for discharges from oil and gas facilities, and
supporting pipeline facilities, engaged
in production, field exploration, drilling, well completion, and
well treatment operations from
potential new sources, existing sources, and new discharges.
The permit coverage area includes Federal waters in the Gulf of
Mexico seaward of the 200
meter water depth for offshore Alabama and Florida and seaward
of the outer boundary of the
territorial seas for offshore Mississippi and Alabama in the
Mobile and Viosca Knoll lease
blocks. This permit is available to facilities located in, and
discharging to, the Federal waters
listed above and does not authorize discharges from facilities
in or discharging to the territorial
sea (within three miles of shore) of the Gulf coastal states or
from facilities defined as "coastal"
or "onshore" (see 40 Code of Federal Regulation (C.F.R.) Part
435, subparts C and D at internet
address: www.epa.gov/epacfr40/chapt-I.info).
2. Types of Operators and Operations Excluded
Any operator seeking to discharge drill fluids, drill cuttings,
well completion, well treatment
or well workover fluids or produced water within 1000 meters of
an Area of Biological Concern
(ABC) or within 1000 meters of a Federally Designated Dredged
Material Disposal Site is
ineligible for coverage under this general permit and must apply
for an individual permit. Any
leases which are currently under moratorium are excluded from
inclusion under this general
permit.
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For the purpose of this permit, Operator means any party that
meets either of the following
criteria and pertains only in the context of discharges
associated with oil and gas exploration,
development, and production activities covered under this
permit:
1. Primary Operator The party possesses the lease of the block
where the exploration,
development, or production activity will take place and has
operational control over
exploration, development, or production activities, including
the ability to hire or fire
contractors who conduct the actual work that results in
discharges regulated by the permit
(i.e., the lease holder) or designated operator who registers
with the Bureau of Ocean
Energy Management (BOEM); or
2. Day-to-day Operator - The party has a day-to-day operational
control of those activities
at an exploration, development, or production project which are
necessary to ensure
compliance with the permit (i.e., designated operator or
contractor); or
3. Vessel Operator The party has operational control over all
vessel or other mobile
facility with cooling water intake structures subject to Clean
Water Act (CWA) Section
316(b). [Note: A vessel or mobile facility which engages in an
exploration, development,
or production activity is subject to this permit even if it is
not subject to CWA Section
316(b).]
The primary operator must file an NOI for discharges to be
covered by this permit. Other
operators or vessel operators must file an NOI to cover
discharges directly under their control but
beyond primary operators control, if such discharges are not
covered by the NOI filed by the
primary operator.
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Permit coverage will not be extended to non-operational
facilities, planned facilities or
planned wells, i.e., those on which no production and no
discharges have taken place in the two
years prior to the effective date of this general permit, until
such time that documentation is
submitted to EPA that an Exploration Plan (EP), Development
Operational Coordination
Document (DOCD) or Development Production Plan (DPP) has been
submitted to BOEM or
approved by BOEM.
3. General Permit Applicability
In accordance with 40 C.F.R. 122.28(b)(3) and 122.28(c), the
Regional Administrator
may require any person authorized by this permit to apply for
and obtain an individual NPDES
permit when:
a. The discharge(s) is a significant contributor of pollution;
b. The discharger is not in compliance with the conditions of this
permit; c. A change has occurred in the availability of the
demonstrated technology or practices for the control or abatement
of pollutants applicable to the point sources; d. Effluent
limitation guidelines are promulgated for point sources covered by
this permit, which were not already subject to an effluent
guideline; e. A Water Quality Management Plan containing
requirements applicable to such point source is approved; f. It is
determined that the facility is located in an ABC; g. Circumstances
have changed since the time of the request to be covered so that
the discharge is no longer appropriately controlled under the
general permit, or either a temporary or permanent reductions or
elimination of the authorized discharge is necessary; h. Other
relevant factors (i.e., permittee was in non-compliance status with
an individual NPDES permit for offshore oil and gas
operations).
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The Regional Administrator may require any operator authorized
by this permit to apply for
an individual NPDES permit only if the operator has been
notified in writing that an individual
permit is required.
Any operator authorized by this permit may request to be
excluded from the coverage of this
general permit at any time by applying for an individual permit.
Such operator shall submit the
appropriate application forms to the Regional Administrator.
When an individual NPDES permit
is issued to an operator otherwise subject to this permit, the
applicability of this permit to the
owner or operator is automatically terminated on the effective
date of the individual permit.
A source excluded from coverage under this general permit solely
because it already has an
individual permit may request that its individual permit be
revoked, and that it be considered for
coverage by this general permit. Revocation of the individual
permit will occur upon approval of
coverage (see Part I.A.4, below) under this permit.
4. Notification Requirements (Existing Sources and New
Sources)
A Notice of Intent (NOI) requesting coverage in accordance with
the general permit
requirements shall state whether the permittee is requesting
coverage under the requirements for
an existing source or requirements for new source, as well as
all the following information.
Please indicate N/A for those items that are not applicable to
the coverage:
a. the legal name and address of the owner or operator;
b. Type of operator primary operator, day-to-day operator, or
vessel operator (see Part
I.A.2)
c. the facility name, OCS number location, including the lease
block assigned by BOEM, or
if none, the name commonly assigned to the lease area;
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d. the number and type of facilities and activities proposed
within the lease block;
e. a map with longitude and latitude of the facility location
and of the expected discharges
identified by the nomenclature used in Part I.B.1 - 11.
Additional information may be
requested by the Director regarding miscellaneous
discharges;
f. the date on which the owner/operator commenced/will commence
on-site construction,
including:
i). any placement assembly or installation of facilities or
equipment; or
ii). the clearing or removal of existing structures or
facilities.
g. the date on which the facility plans to commence exploration
activities at the site, if
applicable;
h. the date on which the owner/operator entered into a binding
contract for the purchase of
facilities or equipment intended to be used in its operation
within a reasonable time (if
applicable);
i. the date on which the owner/operator plans to commence
development;
j. the date on which the owner/operator plans to commence
production;
k. technical information on the characteristics of the sea
bottom in accordance with BOEM
Notice to Lessees (NTL) no. 2008-G05, Shallow Hazards Program,
or the most current
BOEM guidelines for shallow hazard investigation and analysis
within 300 meters (965
feet) of the discharge point. For those facilities that
submitted this information to EPA
Region 4 as part of the previous NPDES general permit
(GEG460000), only indicate the
previous submittal date of the information to meet the
requirement of this NOI element.
l. for facilities in less than 100 meters water depth for
offshore Mississippi and Alabama in
the Mobile and Viosca Knoll lease blocks, permittees must submit
a Live-Bottom Survey
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using either digital high-resolution acoustic data (sidescan
sonar) or photo documentation.
The acoustic data may be either new data acquired for this
purpose or data obtained by the
permittee for lease or site-specific surveys in compliance with
BOEM requirements, as per
NTL No. 2008-G04 Information Requirements for Exploration Plans
and Development
Operations Coordination Documents, or most current BOEM
guidelines. Digital (or
digitized analog data) sidescan sonar data obtained by survey
methods described in NTL
No. 2008-G05 Shallow Hazard Program, or most current BOEM
guidelines, if sufficient,
may be used as the source of acoustic data for preparation of a
Live-Bottom Survey report.
EPA will consider all natural or artificial hard structure
detected by acoustic data to be
live-bottom unless other data (i.e., video, still photographs,
diver visual, etc.) determines
otherwise. Permittees choosing to continue providing photo
documentation will continue
to conduct such surveys, as per NTL No. 2004-G05, attachment 7,
or most current BOEM
guidelines. Final siting of proposed outfalls must be no further
than 500 meters from the
proposed surface location. See Part I.D.5 for specific permit
requirements pertaining to
preparation of reports using high resolution acoustical data.
For those facilities that
submitted this information to EPA Region 4 as part of the
previous NPDES general
permit, only indicate the previous submittal date of the
information to meet the
requirement of this NOI element;
m. the type of drilling fluids to be used (e.g., water-based
and/or synthetic-based);
n. documentation that an Application for Permit to Drill (APD)
has been submitted to BSEE
and the, EP, DOCD or DPP has been submitted to BOEM or approved
by BOEM;
o. for facilities installed after March 4, 1993, the NOI must
also identify that the facility is a
new source and state the date on which the facilitys protection
from more stringent new
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source performance standards or technology-based limitations
ends. That date is the
soonest of ten years from the date that construction is
completed, ten years from the date
the source begins to discharge process or non-construction
related wastewater, or the end
of the period of depreciation or amortization of the facility
for the purposes of Section 167
or 169 (or both) of the Internal Revenue Code of 1954;
p. the general permit coverage number for the previous general
permit and/or the individual
NPDES permit number of any individual permit issued by EPA
Region 4 for this activity;
q. for production platforms, indicate the estimated distance (in
meters) from the platform to
the nearest Federally Designated Dredged Material Ocean Disposal
Site;
r. any permit violations or under the previous Region 4 General
Permit for the facility;
s. indicate if Phase III of EPAs Cooling Water Intake Structure
Rule (CWIS) applies to the
facility for which you are applying for coverage under this
permit. Also indicate if the
facility plans to comply under Track I or Track II of the CWIS.
See Part I.D.3. Note that
the Phase III CWIS rule applies to new offshore oil and gas
extraction facilities for which
construction commenced after July 17, 2006, that meet the
following criteria: 1) it is a
point source that uses or proposes to use a cooling water intake
structure; 2) it has at least
one cooling water intake structure that uses at least 25% of the
water it withdraws for
cooling purposes; 3) it has a design intake flow greater than
two million gallons per day
(MGD). Use of a cooling water intake structure includes
obtaining cooling water by any
sort of contract or arrangement with an independent supplier (or
multiple suppliers) of
cooling water if the supplier or suppliers withdraw(s) water
from waters of the United
States. The threshold requirement that at least 25% of water
withdrawn be used for
cooling purposes must be measured on an average monthly basis. A
new offshore oil and
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gas extraction facility meets the 25% cooling water threshold
if, based on the new
facilitys design, any monthly average over a year for the
percentage of cooling water
withdrawn is expected to equal or exceed 25% of the total water
withdrawn.
t. if known, indicate the name and NPDES permit coverage number
under GEG460000 for
vessel operators/contractors that are, or will be, performing
work at your facility that are
new oil and gas facilities subject to Phase III of the CWIS
Rule.
u. Information on the specific chemical composition of any
additives currently being used or
proposed for use in well treatment, completion or workover
operations or as biocides for
sump/drain systems. If the information on the additive is not
known at the time of the
submittal of this NOI, operators shall include the information
in a report that shall be
submitted on to EPA Region 4 on September 30th of each year
Aside from submitting this
information with the NOI, this information is also required to
be recorded and retained on
site for no less than five years from the issuance date of the
permit. See Part I.6.a.iii.
v. Certification statement per 40 C.F.R. 122.22(d) and signature
of the responsible party
per 40 C. F.R 122.22(a).
Operators with coverage under the previous general permit that
was administratively
continued (i.e., a request for continued coverage received prior
to) must submit a new NOI to be
covered under this permit no later than 30 days from the
effective date of this permit. All
facility owners for newly acquired leases must submit a written
NOI prior to the date of
discharge and no later than 14 days prior to the expiration date
of this permit. All NOIs shall be
signed in accordance with 40 C.F.R. 122.22.
EPA will accept a written NOI until December 31, 2016. Beginning
January 1, 2017 through
the expiration date of this permit, all NOI must be submitted
electronically. For NOI submitted
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in writing, the effective date of coverage will be the
postmarked date of the NOI, or if the
postmarked date is illegible, the effective date of coverage
will be two days prior to the receipt
date of the NOI. Beginning January 1, 2017, the effective date
of coverage submitted
electronically will be the date of the request. EPA will notify
the applicant within 21 days of the
receipt date regarding the new permit coverage number(s) and
effective date of permit coverage.
If an NOI is determined to be incomplete, EPA will notify the
applicant within 21 days of receipt
of the NOI regarding any discrepancies, and/or possible
termination of coverage. Information
regarding electronic submittals of NOIs is contained in Part III
of this permit.
5. Operational Facilities
a. Change in designation from existing source to new source
Operators obtaining coverage under the existing source general
permit for exploration
activities (existing source) must send a new NOI for coverage of
development and production
activities as new source 14 days prior to commencing such
operations. All NOIs requesting
coverage should be sent by certified mail to: Director, Water
Protection Division, U.S. EPA
Region 4, Sam Nunn Federal Center, 61 Forsyth Street, S.W.,
Atlanta, GA 30303-8960.
b. No Activity Notification
For any activity for which no discharge is occurring, the
operator shall submit a No
Activity list each calendar quarter along with the quarterly
submittal of the Discharge
Monitoring Report (DMR). The No Activity list shall include:
(i) the NPDES general permit coverage number assigned to the
facility,
(ii) the lease block designation and,
(iii) a certification statement signed in accordance with Part
II.D.12. of this permit.
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All NOIs, No Activity lists, and any subsequent reports required
under this permit shall
contain a signed certification statement (see Part II.D.12) and
shall be sent by certified mail to
the address given above.
6. Non-Operational Facilities
Non-operational facilities, planned facilities or planned wells
are only eligible for coverage
under this general permit after documentation has been submitted
to EPA indicating that an EP,
DOCD or DPP, has been submitted to, or approved by, BOEM.
7. Termination of Operations
Lease block operators shall notify the Director (at the address
above) within 60 days after the
permanent termination of discharges from their facility.
Information regarding electronic
submittals of Notices of Termination (NOTs) is contained in Part
III of this permit.
8. Intent to be Covered by a Subsequently Issued Permit
This permit shall expire five years from the effective date of
the permit. A letter requesting
coverage under a subsequent general permit must be submitted no
later than the expiration date
of this permit. (NOTE: Due to this being a general permit, this
stipulation supersedes the 180-
day time frame in Part II.D.11). The request letter must list
the facilities to be covered under the
subsequent permit, their current permit coverage numbers, and be
certified in accordance with
Part II.D.12. If reissuance of this general permit does not
occur before its expiration date and the
permittee has submitted the request letter, continued coverage
under this permit will be allowed
until the effective date of the reissued general permit. If the
permittee is notified by EPA of the
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need to submit application forms for an individual permit and a
letter requesting coverage under
the subsequent permit was submitted, continued coverage under
this general permit will be
allowed until the effective date of the individual permit issued
to the applicable facility.
Permittees that fail to notify the Director, during the term of
this permit, of their intent to be
covered by a subsequently issued permit cannot obtain continued
authorization to discharge after
the expiration date of this permit and will be operating without
NPDES permit coverage until
they apply for and obtain coverage under the subsequently issued
general permit or apply for,
and receive, an effective individual NPDES permit. All letters
requesting coverage under a
subsequently issued general permit should be sent by certified
mail to: Director, Water
Protection Division, U.S. EPA Region 4, Sam Nunn Federal Center,
61 Forsyth Street, S.W.,
Atlanta, GA 30303-8960.
9. Transfer of General Permit Coverage
This permit is not transferable to any entity except after
written notice to the Director and
subsequent written approval by the Director. The request for
transfer shall include the permit
coverage number, the OCS number, the facility name, and lease
block name, the name of the
existing permittee, name of the operator the coverage is being
transferred to, and the projected
date the transfer is to become effective. Submittal of a new NOI
is not required for the transfer
of permit coverage. The request must contain a certification
statement (see Part II.D.12.d.) and
be signed and dated by officials from each operating company.
The Director may require
modification or revocation and reissuance of the permit coverage
to change the name of the
permittee and incorporate such other requirements as may be
necessary under the Clean Water
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Act (CWA). (The transfer of permit coverage requirements in this
section supersede the
Transfer of Ownership of Control requirements set forth in Part
II.D.3 of this permit.)
B. Effluent Limitations and Monitoring Requirements for New and
Existing Sources
Note: EPA published the final rule Guidelines Establishing Test
Procedures for the Analysis of
Pollutants Under the Clean Water Act: Analysis and Sampling
Procedures in Federal Register,
Vol. 77, No. 97, May 18, 2012. Any recent or future changes or
incorporation of new testing
protocol or methods in the Effluent Limitation Guideline at 40
C.F.R. Part 435 supersede the
applicable requirements in this permit.
The following limitations and monitoring requirements are
summarized in Part V, Table 1 of
this permit. Note all samples must be representative of the
effluent. Permittees are not allowed
to filter samples.
1. Drilling Fluids
a. Prohibitions
i. Non-Aqueous Based Drilling Fluids (NAFs) [including
Synthetic-Based
Drilling Fluids (SBFs)]. There shall be no discharge of NAFs,
except that which
adheres to cuttings, or which are considered de minimus
discharges (see Part
I.D.1) or as small volume discharges (see Part I.D.2).
Exception - NAFs may be used as a carrier fluids (e.g.,
transporter fluid), lubricity additive or
pill in water-based drilling fluids, and may be discharged with
those drilling fluids provided
the discharge continues to meet the no Free Oil limit, the
96-hour LC50 toxicity limits, and
the pill is removed prior to discharge.
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ii. Oil-Based Drilling Fluids. There shall be no discharge of
oil-based drilling
fluids and inverse emulsion drilling fluids.
iii. Oil-Contaminated Drilling Fluids. There shall be no
discharge of drilling
fluids to which waste engine oil, cooling oil, gear oil or any
lubricants which have
been previously used for purposes other than borehole
lubrication have been
added.
iv. Diesel Oil. There shall be no discharge of drilling fluids
to which contain
diesel oil.
v. No Discharge Near Areas of Biological Concern. Unless
otherwise authorized
by the Director, there shall be no discharge of drilling fluids
and drill cuttings
from those facilities within 1000 meters (or as determined by
the Director) of an
ABC.
vi. No Discharge Near Federally Designated Dredged Material
Ocean Disposal
Sites. Unless otherwise authorized by the Director, there shall
be no discharge of
any drilling fluids and drill cuttings from those facilities
within 1000 meters (or as
determined by the Director) of a Federally Designated Dredged
Material Ocean
Disposal Site. See 40 C.F.R. 228.15(f) for a list of sites
covered by this general
permit.
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b. Limitations
i. Mineral Oil. Mineral oil may be used only as a carrier fluid
(e.g., transporter
fluid), lubricity additive, or pill. If mineral oil is added to
a water-based drilling
fluid, the drilling fluid may not be discharged, unless the
96-hr LC50 of the
drilling fluid is greater than 30,000 ppm (3% by volume) using
the Suspended
Particulate Phase (SPP) Toxicity Test and the sample passes the
Static Sheen Test
for free oil. The analytical methods for the SPP Toxicity Test
and free oil are
contained in Part I.B.1(b)(3) and (4) below. Samples must be
taken at the nearest
accessible location prior to discharge, or prior to combining
with any other
wastewaters.
ii. Cadmium and Mercury in Barite. There shall be no discharge
of drilling fluids
to which barite has been added if such barite contains mercury
in excess of 1.0
mg/kg (dry weight) or cadmium in excess of 3.0 mg/kg (dry
weight). The
permittee shall analyze a representative sample of each supply
of stock barite
prior to drilling each well and submit the results for total
mercury and cadmium
on the DMR. If more than one well is being drilled at a site,
new analyses are not
required for subsequent wells, provided that no new supplies of
barite have been
received since the previous analysis. In this case, the results
of the previous
analysis should be used for completion of the DMR.
Alternatively, the permittee
may provide certification, as documented by the supplier(s),
that the barite being
used on the well will meet the above limits. The concentration
of the mercury and
cadmium in the barite shall be reported on the DMR as documented
by the
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supplier. Analyses for cadmium shall be conducted by EPA Methods
200.7,
200.8 or EPA Method 3050 B followed by 6010 B or 6020A (EPA SW
846), or
more recently approved EPA methods, and results shall be
expressed in mg/kg
(dry weight) of stock barite. Analysis for mercury shall be
conducted using EPA
Method 245.7 or EPA method 7471 A (EPA SW 846), or most recently
approved
EPA methods, and expressed as mg/kg (dry weight) of stock
barite.
iii. Toxicity. Discharged water-based drilling fluids shall meet
both a daily
minimum and a monthly average minimum effluent toxicity
limitation of 30,000
ppm (3.0% by volume), using a volumetric mud-to-water ratio of 1
to 9. The
analytical method is cited in 40 C.F.R. Part 435, Appendix 2 of
subpart A,
entitled, Drilling Fluid Toxicity Test. Monitoring shall be
performed at least
once per month by a grab sample taken from beneath the shale
shaker for both the
daily minimum and the monthly average minimum. If there are no
returns across
the shaker, the sample must be taken from a location that is
characteristic of the
overall mud system to be discharged. An end-of-well sample (See
definition in
Part V.B) is also required. The end-of-well test sample can also
be used for the
last monthly grab sample. The lowest daily minimum and lowest
monthly average
for the quarterly reporting period must be reported on the DMR.
Copies of the
summary sheets for laboratory reports must also be submitted
with the DMR. If a
failure occurs, the facility must submit the entire laboratory
report with the DMR.
Samples for this parameter must be taken at the nearest
accessible location prior
to discharge, or prior to combining with any other
wastewaters.
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iv. Free Oil. No free oil shall be discharged. Monitoring shall
be performed
once per week using the Static Sheen Test method in accordance
with the method
provided in Part V.A.3, as published in 40 C.F.R. Part 435,
Appendix 1 of subpart
A. The results of each sheen test must be recorded for the
fluids that are
discharged and the number of days a sheen is observed must be
reported on the
DMR.
v. Maximum Hourly Discharge Rate. The maximum discharge rate
(water-based
drilling fluids) shall not exceed 1,000 barrels (bbls) per hour.
The maximum
hourly discharge rate for each month must be recorded. The
highest hourly
discharge rate for the quarterly reporting period must be
reported on the DMR in
barrels/hour.
Exception - The Maximum Hourly Discharge Rate Limitation shall
not apply to Water-Based
Drilling Fluids discharged prior to the installation of the
marine riser.
c. Monitoring Only Requirements
In addition to the above limitations, the following monitoring
and reporting requirements
also apply to drilling fluids discharges.
i. Drilling Fluids Inventory. The permittee shall maintain a
precise chemical
usage record of all constituents and their total volume and mass
added for each
well. Information shall be recorded and retained for the term of
the permit.
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ii. Volume. The total monthly volume (bbl/month) of bulk
discharged drilling
fluids must be estimated and recorded. The highest monthly
volume (in
bbl/month) and the average volume during the monitoring period
shall be reported
on the DMR.
2. Drill Cuttings
Except for the maximum hourly discharge rate, the permit
prohibitions and limitations that
apply to drilling fluids also apply to fluids that adhere to
drill cuttings. Any permit condition that
applies to the drilling fluid system, also applies to cuttings
discharges. Monitoring requirements,
however, may not be the same.
a. Prohibitions
i. Cuttings from Oil-Based Drilling Fluids. The discharge of
cuttings is prohibited
when they are generated while using an oil-based or invert
emulsion mud.
ii. Cuttings from Oil Contaminated Drilling Fluids. There shall
be no discharge
of cuttings that are generated using drilling fluids that
contain waste engine oil,
cooling oil, gear oil or any lubricants which have been
previously used for
purposes other than borehole lubrication.
iii. Cuttings Generated Using Drilling Fluids Which Contain
Diesel Oil. There
shall be no discharge of drill cuttings generated using drilling
fluids which contain
diesel oil.
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iv. Cuttings Generated Using Mineral Oil. The discharge of
cuttings generated
using drilling fluids which contain mineral oil is prohibited
except when the
mineral oil is used as a carrier fluid (e.g., transporter
fluid), lubricity additive, or
pill.
v. No Discharge Near Areas of Biological Concern. There shall be
no discharge
of drill cuttings from those facilities within 1000 meters (or
as determined by the
Director) of an ABC.
vi. No Discharge Near Federally Designated Dredged Material
Ocean Disposal
Sites. There shall be no discharge of any drilling fluids, drill
cuttings or produced
waters from those facilities within 1000 meters (or as
determined by the Director)
of a Federally Designated Dredged Material Ocean Disposal Site.
See 40 C.F.R.
228.15(f) for a list of sites in the general permitting
area.
vii. Cuttings Generated Using Non-Aqueous Based Drilling Fluid.
There shall be
no discharge of non-aqueous based drilling fluid, except that
which adheres to
cuttings, de minimus discharges (see Part I.D.1) and small
volume discharges (see
Part I.D.2 ).
Exception - NAFs may be used as a carrier fluid (e.g.,
transporter fluid), lubricity additive or
pill in water-based drilling fluids and discharged with those
drilling fluids provided the
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discharge continues to meet the no free oil and 96-hour LC50
toxicity limits, and a pill is
removed prior to discharge.
b. Limitations which apply to all drill cuttings
i. Mineral Oil. There shall be no discharge of mineral oil.
Exception - Cuttings from a water-based mud system may be
discharged when
mineral oil pills or mineral oil lubricity additives have been
introduced if they
meet the limitations below for aquatic toxicity and free
oil.
ii. Free Oil. No free oil shall be discharged. Monitoring shall
be performed on
cuttings discharges once per week using the Static Sheen Test
method in
accordance with the method provided in Part V.A.3. Samples must
be taken at
the nearest accessible location prior to discharge, or prior to
combining with any
other wastewaters. There shall be no discharge of cuttings that
fail the static
sheen test. The results of each sheen test for fluids that are
discharged must be
recorded and the number of observations of a static sheen must
be reported on the
DMR.
iii. Suspended Particulate Phase Toxicity. Discharged cuttings
shall meet both a
daily minimum and a monthly average minimum effluent toxicity
limitation of at
least 30,000 ppm (3.0% by volume), using a volumetric
mud-to-water ratio of 1 to
9. The analytical method is cited in 40 C.F.R. Part 435,
Appendix 2 of subpart A,
entitled, Drilling Fluid Toxicity Test. Monitoring shall be
performed at least
once per month by taking a grab sample from beneath the shale
shaker for both
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the daily minimum and the monthly average minimum limits. The
toxicity test
may be satisfied by the same sample used for the drilling fluid.
An end-of-well
sample is also required. The end-of-well test sample may also be
used as the last
monthly grab sample. The lowest daily minimum value for the
12-month
reporting period as well as the lowest monthly average test
result must be reported
on the DMR. Copies of the summary sheets for laboratory reports
also must be
submitted with the DMR. If a failure occurs, the facility must
submit the entire
laboratory report with the DMR.
iv. Mercury and Cadmium in Stock Barite. There shall be no
discharge of drilling
fluids to which barite has been added, if such barite contains
mercury in excess of
1.0 mg/kg (dry weight) or cadmium in excess of 3.0 mg/kg (dry
weight). The
permittee shall analyze a representative sample of each supply
of stock barite
prior to drilling each well and submit the results for total
mercury and total
cadmium on the DMR. If more than one well is being drilled at a
site, new
analyses are not required for subsequent wells, provided that no
new supplies of
barite have been received since the previous analysis. In this
case, the results of
the previous analysis should be used for completion of the DMR.
Alternatively,
the permittee may provide certification, as documented by the
supplier(s), that the
barite being used on the well will meet the above limits. The
concentration of the
mercury and cadmium in the barite shall be reported on the DMR
as documented
by the supplier. Analyses for cadmium shall be conducted by EPA
Methods
200.7, 200.8 or EPA Method 3050 B followed by 6010 B (EPA SW
846) and
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results expressed in mg/kg (dry weight) of stock barite.
Analysis for mercury
shall be conducted using method 245.7 or EPA Method 7471 A (EPA
SW 846),
and expressed as mg/kg (dry weight) of stock barite.
c. Discharge Limitations Applicable to Non-Aqueous Based Drill
Cuttings
Except for the toxicity testing requirements for drilling fluids
in Part I.B.1.b.(iii), all
the limits for drill cuttings in Part I.B.2.(b) above, apply to
synthetic-based drill cuttings.
i. Formation Oil. There shall be no discharge of formation oil.
Monitoring of the
drilling fluids shall be performed as follows:
(1). Once prior to drilling using the gas chromatography/mass
spectrometry
test (GC/MS) method specified in Appendix 5 of 40 C.F.R. Part
435, subpart A.
Alternatively, the permittee may provide certification, as
documented by the
supplier(s) that the drilling fluid being used on the well
contains no formation oil
as determined using the GC/MS method in Appendix 5 of 40 C.F.R.
Part 435,
subpart A.
(2). Once per week during drilling using the Reverse Phase
Extraction (RPE)
test method specified in Appendix 6 of 40 C.F.R. Part 435,
subpart A. If an
operator wishes to confirm the results of the RPE method, the
GC/MS method
may be used, and results of this method shall supersede the
results of the RPE
method. Alternatively, the operator may use the GC/MS method
instead of the
RPE method.
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As an alternative to using the crude oil standard in Appendix 5
and 6 of 40 C.F.R.
Part 435 A, the permittee may use National Institute of
Standards and Technology
method no. 2779, Gulf of Mexico Crude Oil Standard.
All test results shall be reported with the DMR.
ii. Drilling Fluid Sediment Toxicity Ratio. The sediment
toxicity test ratio shall
not exceed 1.0 and shall be calculated based on the
following:
Drilling Fluid Sediment = 4-day LC50 of C16-C18 internal olefin
reference drilling fluid Toxicity Ratio 4-day LC50 of drilling
fluid removed from the drill
cuttings at the solids control equipment
The approved test method is ASTM method no. E1367-92 (or the
most current
EPA approved method) and monitoring for this parameter shall be
once per month
per well. Samples shall be collected and analyzed in accordance
with the
sampling protocol in Part V.12.
iii. Base Fluid Retained on Cuttings. For NAFs that meet the
stock limitation of
C16-C18 internal olefin, the maximum weighted mass ratio
averaged over all non-
aqueous-based drilling fluid well sections shall not exceed 6.9
g NAF per 100 g of
wet drill cuttings. For NAFs that meet the stock limitation of
C12-C14 esters or
C8 ester, the maximum weighted mass ratio averaged over all NAF
well sections
shall not exceed 9.4 g non-aqueous-based drilling fluid per 100
g of wet drill
cuttings. A default value of 14% of base fluid retained on drill
cuttings may be
used for determining compliance with the base fluids retained on
cutting limit
where seafloor discharges are made from dual gradient drilling.
In those cases,
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15% will be used as a default value for the mass fraction of
cuttings discharged at
the sea floor. The default values will be averaged with results
obtained from daily
monitoring to determine compliance with the retention
limitations. Monitoring
for this parameter shall be once per day by grab sample except
when meeting the
conditions of the Best Management Practices described in Part
I.V.3.g., or one
sample for every 500 feet drilled, up to three samplings per
day, using the
American Petroleum Institute (API) Retort method specified in 40
C.F.R. Part
435, subpart A of Appendix 7. The weighted mass ratio averaged
over all non-
aqueous-based drilling fluid well sections shall be reported on
the DMR. The
sample for the drilling fluid retained on cuttings shall be
taken at the solids
control equipment.
d. Base Drilling Fluid Stock Limitations Applicable to
Non-Aqueous Based Drill Cuttings
i. Polynuclear Aromatic Hydrocarbon (PAH) Content. The PAH mass
ratio shall
not exceed 1x10-5. Monitoring shall be by grab sample taken once
per year on
each fluid blend using EPA Method 1654A (or the most current
version), in
conjunction with the following equation:
PAH mass ratio = mass (g) of PAH (as phenanthrene) mass (g) of
stock base fluid
The PAH ratio shall be reported on the DMR.
ii. Stock Drilling Fluid Sediment Toxicity Ratio. The sediment
toxicity ratio
shall not exceed 1.0, and shall be calculated as follows:
For NAF base fluid of C16-C18 internal olefin,
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Sediment Toxicity Ratio = 10-day LC50 of C16-C18 internal olefin
reference fluid 10-day LC50 of stock base fluid
For NAF base fluids of 100% C12-C14 ester or C8 ester
content,
Base Fluid Sediment Toxicity Ratio = 10-day LC50 of C12-C14
ester or C8 ester reference base fluid* 10-day LC50 of stock base
fluid
* Chemical Abstract No. 135800-37-2
Monitoring for the parameter shall be performed at least once
per year on each
fluid blend using the 10-day LC50 sediment toxicity test
specified in ASTM E1367-92 (or
the most current EPA approved method), and reported on the DMR.
Samples shall be
collected and analyzed using the sampling protocol in Part
V.12.
iii. Biodegradation Rate Ratio. The biodegradation rate ratio of
the stock base
fluid shall not exceed 1.0, and shall be calculated using the
following equation:
For NAF base fluid of C16-C18 internal olefin,
Biodegradation = Cumulative gas production (ml) of C16-C18
internal olefin reference base Rate Ratio fluid at 275
days_____________________________ Cumulative gas production (ml) of
stock base fluid at 275 days
For NAF base fluid of 100% C12-C14 ester or C8 ester
content,
Biodegradation = Cumulative gas production (ml) of C12-C14 ester
or C8 ester reference base Rate Ratio fluid* at 275
days____________________________ Cumulative gas production of (ml)
of stock base fluid at 275 days
* Chemical Abstract No. 135800-37-2
Monitoring for the parameter shall be performed at least once
per year on each
fluid blend using International Standards Organization (ISO)
Method 11734:1995 (or
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the most current EPA approved method) and results reported on
the DMR. See Parts
V.13 and 14 for additional requirements. Samples shall be
collected and analyzed
using the sampling protocol in Part V.12.
Exception - Stock limitations are designed to ensure that only
base fluids meeting Best Available
Technology (BAT) criteria are added to existing drilling fluids.
As long as fluids or blends of
fluids that are added to a built whole mud meet stock
limitations criteria, it is acceptable to mix a
base fluid to a built whole mud that differs from that
originally used to make that mud. It is also
acceptable to mix together two built whole mud systems that
contain different base fluids so long
as they are themselves built with base fluids that are compliant
with the stock limitations.
Operators choosing to mix previously compliant fluids, or blends
of fluids, must analyze the
mixture to show compliance with the limitations for:
Formation Oil (see Part I.B.2.c.i (1)),
SPP toxicity (see Part I.B.1.b.iii), and
Drilling Fluid Sediment Toxicity (see Part I.B.2.c.ii).
All test results shall be submitted with the DMR.
e. Monitoring Only Requirements
Volume. The monthly total discharge of drill cuttings must be
estimated. The
estimated highest monthly volume (in bbl/month) and the average
volume for the
monitoring period for cuttings discharged shall be reported on
the DMR.
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3. Produced Water
Produced water is defined in Part V.B. and includes process
water generated from the
monoethylene glycol (MEG) reclamation processes including salt
slurry generated from the
salt centrifuge unit. This wastewater may be discharged
separately from produced waters via
outfall 014 (i.e., is not mixed and discharged with produced
water via outfall 004). Permit
requirements and limitations are the same as those for produced
waters as stated in Part 3.a.,
b., and c., below.
a. Prohibitions
i. No Discharge Near Areas of Biological Concern. There shall be
no discharge
of produced water from those facilities within 1000 meters (or
as determined by
the Director) of an ABC.
ii. No Discharge Near Federally Designated Dredged Material
Ocean Disposal
Sites. There shall be no discharge of produced water from those
facilities within
1000 meters (or as determined by the Director) of a Federally
Designated
Dredged Material Ocean Disposal Site. See 40 C.F.R. 228.15(f)
for a list of
sites in the general permitting area.
b. Limitations
i. Oil and Grease. Produced water discharges shall not exceed
both a daily
maximum limitation of 42.0 mg/l and a monthly average limitation
of 29.0 mg/l
for oil and grease.
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ii. Toxicity. Produced water discharges must meet the limiting
permissible
concentration (LPC) at the edge of a 100-meter mixing zone. The
LPC is defined
as the No Observed Effect Concentration (NOEC). The LPC must be
equal to, or
greater than, the predicted effluent concentration at the edge
of a 100-meter
mixing zone. Predicted effluent concentrations, referred to as
critical dilutions,
are presented in Tables 3 and 4 of Appendix A for a range of
discharge rates and
pipe diameters. The critical dilution shall be determined using
Tables 3 and 4 of
Appendix A of this permit based on the highest monthly average
discharge rate
for the three months prior to the month in which the test sample
is collected,
discharge pipe diameter, and depth difference between the
discharge pipe and the
sea bottom. Facilities which have not previously reported
produced water flow on
the DMR shall use the estimated monthly average flow that was
discharged
during the first three months of produced water flow for
determining the critical
dilution from Tables 3 and 4 of Appendix A of this permit.
The NOEC shall be calculated by conducting 7-day chronic
toxicity tests in
accordance with methods published in Short Term Methods for
Estimating the
Chronic Toxicity of Effluents and Receiving Water to Marine and
Estuarine
Organisms (EPA/821-R-02-014), or most current edition.
For facilities that had not previously reported produced water,
testing to determine
the NOEC shall begin after the third month of produced water
discharge and shall
be done every two months until the permittee demonstrates
compliance with three
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consecutive produced water toxicity tests and reports those
results. Permittees
that comply with the toxicity limit for three consecutive
produced water toxicity
tests will be allowed to reduce sampling to a frequency of once
every six months.
Permittees that were covered under the previous general permit,
and that are
currently performing routine toxicity tests every six months,
shall continue testing
with a frequency of once every six months. If at any time, a
test result indicates a
failed test, the permittee must resume testing at a greater
frequency, as set forth in
Part V.A.15, until such time that the facility demonstrates
compliance through
three consecutive tests. If a new well is drilled into a
formation currently not
producing, which contains produced water, the permittee shall
perform a new
toxicity test on the discharge beginning after the end of the
first three months of
flow.
The results for both species shall be reported on the DMR. See
Part V.A.15 of this
permit for Whole Effluent Toxicity Testing Requirements.
Samples must be taken at the nearest accessible location prior
to discharge, or prior to
combining with any other wastewaters. In the case where seawater
is added in
accordance with the exception below, samples may be taken
downstream of the point
where seawater is added.
Exception - Permittees wishing to increase mixing may use a
horizontal diffuser, add seawater,
or may install multiple discharge ports (e.g., vertical
diffuser). Permittees using a horizontal
diffuser or multiple discharge ports shall install the system
such that the NOEC is greater than or
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equal to the critical dilution. The projected percent effluent
(critical dilution) at the edge of the
mixing zone will be calculated using CORMIX2 (for horizontal
diffusers) and CORMIX1 (for
vertical diffusers), with the following input conditions:
Density Gradient = 0.163 kg/m3/m
Ambient seawater density at diffuser depth (or at surface for
vertical diffuser)
= 1023.0 kg/m3
Produced water density = 1070.2 kg/m3
Current speed = 5 cm/sec (200 m water
depth)
Permittees shall submit a certification that the diffuser,
seawater addition, or
multiple discharge ports has been installed and state the
critical dilution and
corresponding NOEC in the certification. The certification shall
be submitted
along with the first DMR for produced water discharges to:
Director, Water
Protection Division, U.S. EPA Region 4, Sam Nunn Atlanta Federal
Center, 61
Forsyth Street, SW, Atlanta, GA 30303-8960. All modeling runs
shall be retained
by the permittee as part of its NPDES records.
Permittees using vertically aligned multiple discharge
ports/vertical diffuser
shall provide vertical separation between ports which is
consistent with Table 5 of
Appendix A of this permit. When multiple discharge ports are
installed, the depth
difference between the discharge port closest to the seafloor
and the seafloor shall
be the depth difference used to determine the critical dilution
from Tables 3 and 4
of Appendix A of this permit.
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Permittees discharging produced water at conditions other than
those covered
in Tables 3 and 4 of Appendix A (e.g., at a rate greater flows
and pipe diameters)
shall determine the critical dilution using the appropriate
CORMIX model with
the above input parameters. Permittees shall retain the model
runs as part of the
NPDES records.
The critical dilution value shall be based on the port flow rate
(total flow rate
divided by the number of discharge ports) and based on the
diameter of the
discharge port (or largest discharge port if they are of
different styles).
When seawater is added to produced water prior to discharge, the
total
produced water flow, including the added seawater, shall be used
in determining
the critical dilution from Tables 3 and 4 of Appendix A. When
freshwater is
added to produced water prior to discharge, the total produced
water flow,
including the added freshwater, shall be used in determining the
critical dilution
from Table 7 of Appendix A.
Permittees wishing to reduce a produced water flow rate and
thereby the
critical dilution through operational changes must provide to
EPA a description of
the specific changes that were made and the resultant low rate.
The permittee
must certify that this flow rate will not be exceeded for the
remainder of the DMR
period, unless the permittee re-certifies.
c. Monitoring Requirements
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i. Flow. Once per month, an estimate of the flow must be
recorded in units of
barrels per day (bbl/day). The highest monthly discharge flow
rate (in bbl/day)
shall be estimated and reported on the DMR.
ii. Oil and Grease. A grab sample must be taken at least once
per month. The
daily maximum sample may be based on the average concentration
of four grab
samples spaced evenly and weighted by the flow rate and taken
within a 24-hour
period. (Reference Parts II.E.4 and E.7.c). If only one sample
is taken for any one
month, it must meet both the daily and monthly limits. If more
samples are taken,
they may exceed the monthly average for any one day, provided
that the average
of all samples taken meets the monthly limitation. The
gravimetric method is
specified in 40 C.F.R. Part 136. Samples must be taken at the
nearest accessible
location after final treatment and prior to combining with any
other wastewaters.
The highest daily maximum concentration and the highest monthly
average
concentration shall be reported on the DMR.
In addition, a produced water sample shall be collected within
two (2) hours of
when a sheen is observed in the vicinity of the discharge or
within two hours after
startup of the system if it is shut down following a sheen
discovery, and analyzed
for oil and grease.
iii. Visual Sheen. The permittee shall monitor for free oil
using the visual sheen
test method on the surface of the receiving water. Monitoring
shall be performed
once per day when discharging, during conditions when
observation of a sheen on
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40 C.F.R. 122.42(a)(2)(i-iii)the surface of the receiving water
is possible in the
vicinity of the discharge, and when the facility is manned.
4. Deck Drainage
Limitations
Free Oil. No free oil shall be discharged. Monitoring shall be
performed on each day
of discharge during daylight hours using the visual sheen test
method in accordance with
the method provided at Part V.A.4. Discharge of deck drainage
that fails the visual sheen
test shall be a violation of this permit. The results of each
visual must be recorded and
the number of observations of a sheen must be recorded for the
monitoring period and
reported on the DMR. Note: An observation of deck drainage sheen
is not required when
the facility is not being manned.
Biocides: A use of biocide for sump/drain systems to comply
proper operation and
maintenance requirements is permitted for those compounds that
meet the requirement at
40 C.F.R. 122.42(a)(2)(i-iii) (Also see Part II.D.11 of the
permit).
5. Produced Sand
There shall be no discharge of produced sand. Wastes must be
hauled to shore for
treatment and disposal.
6. Well Treatment Fluids, Completion Fluids, and Workover
Fluids
a. Limitations
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i. Free Oil. No free oil shall be discharged. Monitoring shall
be performed prior
to discharge and on each day of discharge using the static sheen
test method in
accordance with the method provided at Part V.A.3. There shall
be no discharge
of well treatment, completion, or workover fluids that fail the
static sheen test.
Samples must be taken at the nearest accessible location after
final treatment and
prior to discharge, or prior to combining with any other
wastewaters. The results
of each sheen test for discharged fluids must be recorded and
the number of
observations of a sheen must be reported for the monitoring
period on the DMR.
ii. Oil and Grease. Well treatment fluids, completion fluids,
and workover fluids
discharges must meet both a daily maximum of 42.0 mg/l and a
monthly average
of 29.0 mg/l limitation for oil and grease. A grab sample must
be taken at least
once per month when discharging. Samples must be taken at the
nearest
accessible location after final treatment and prior to
discharge, or prior to
combining with any other wastewaters. The daily maximum
concentration may
be based on the average of four grab samples spaced evenly and
weighted by the
flow rate and taken within a 24-hour period. (Reference Parts
II.E.4 and E.7.c).
taken within the 24-hour period. If only one sample is taken for
any one month, it
must meet both the daily and monthly limits. If more samples are
taken, they may
exceed the monthly average for any one day, provided that the
average of all
samples taken meets the monthly limitation. The analytical
method is the
gravimetric method, as specified in 40 C.F.R. Part 136. The
highest daily
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maximum and the highest monthly average for the monitoring
period shall be
reported on the DMR.
iii. Priority Pollutants. For well treatment fluids, completion
fluids, and workover
fluids, the discharge of priority pollutants is prohibited
except in trace amounts.
If multiple fluids are mixed, each fluid must be checked for
priority pollutants.
Trace amounts shall mean the amount equal to or less than the
most sensitive
method detection limit listed in 40 C.F.R. Part 136 for the
applicable parameter.
Vendor certification indicating the fluids contain no priority
pollutants is
acceptable for meeting this requirement. Information on the
specific chemical
composition of any additives containing priority pollutants
shall be recorded and
submitted as part of the NOI (see part I.4.u) Any updated
information regarding
chemical composition of new formulations that contain priority
pollutants and
will be used shall be submitted to EPA Region 4 annually no
later than September
30th. Operators may submit this information marked as
Confidential Business
Information, if necessary. Copies of these records should also
be kept on the rig
while the rig is on the permitted location and thereafter at the
permittees shore
base or office. These record retention requirements supersede
those found in Part
II.C.5. of this permit.
Note: If materials added downhole as well treatment, completion,
or workover fluids contain
no priority pollutants as determined by using analytical methods
in 40 C.F.R. Part 136, the
discharge is assumed not to contain priority pollutants.
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iv. Chronic Whole Effluent Toxicity for Well Treatment,
Completion or
Workover fluids Permittess with discharges of well treatment
fluids, completion
or workover lasting four or more consecutive days must monitor
and report the
No Observable Effect Concentration (NOEC) relative to the
predicted effluent
concentration at the edge of a 100-meter mixing zone. Predicted
effluent
concentrations, referred to as critical dilutions, are presented
in Tables 3 and 4 of
Appendix B for a range of discharge rates and pipe
diameters.
Permittees discharging well treatment wastewater at conditions
other than those
covered in Tables 3 and 4 of Appendix A (e.g., at a rate greater
flows, pipe
diameters, or discharge densities) shall determine the critical
dilution using the
appropriate CORMIX model with the input parameters shown below.
Permittees
shall retain the model runs as part of the NPDES records. The
critical dilution
shall be determined using the CORMIX model using the highest
daily average
discharge rate for the three days prior to the day in which the
test sample is
collected, the discharge pipe diameter, the measured discharge
density, and the
depth difference between the discharge pipe and the sea
bottom.
Input Parameters:
Density Gradient = 0.163 kg/m3/m
Ambient seawater density = 1023.0 kg/m3
Well Treatment wastewater density = 1030.0 1680.0 kg/m3
Completion and workover fluids = 1030.0 1680.0 kg/m3
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Current speed = 5 cm/sec (200 m water
depth)
The NOEC shall be calculated by conducting 7-day chronic
toxicity tests in
accordance with methods published in Short Term Methods for
Estimating the
Chronic Toxicity of Effluents and Receiving Water to Marine and
Estuarine
Organisms (EPA/821-R-02-014), or most current edition.
The results for both species shall be reported on the DMR. See
Part V.A.15.a of this
permit for Whole Effluent Toxicity Testing Requirements.
Samples must be taken at the nearest accessible location prior
to discharge. All
modeling runs shall be retained by the permittee as part of its
NPDES records.
v). Acute Whole Effluent Toxicity Testing for Well Treatment,
Completion or
Workover Fluids -The following Acute Whole Effluent Testing
requirements
apply to discharges of well treatment fluids that last less than
4 days. Permittees
must monitor and report the acute critical dilution (ACD) at the
edge of a 100
meter mixing zone. The ACD is defined as 1.0 times the LC50. The
ACD and the
predicted effluent concentration at the edge of a 100 meter
mixing zone must be
reported on the DMR. Predicted effluent concentrations, referred
to as critical
dilutions, are presented in Tables 3 and 4 of Appendix A for a
range of discharge
rates and pipe diameters. Critical dilution shall be determined
using Tables 3 and
4 of this permit based on the most recent discharge rate,
discharge pipe diameter,
and water depth between the discharge pipe and the ocean bottom.
LC50 shall be
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calculated by conducting 48-hour, non static renewal, toxicity
tests once per
discharge using Mysidopsis bahia and Menidia beryllina (Inland
silverside
minnow). Additional acute toxicity testing requirements are
contained in Part
V.15.b of this permit.
Permittees discharging well treatment wastewater at conditions
other than those
covered in Tables 3 and 4 of Appendix A (e.g., at a rate greater
flows, pipe
diameters, or discharge densities) shall determine the critical
dilution using the
appropriate CORMIX model with the input parameters shown below.
Permittees
shall retain the model runs as part of the NPDES records. The
critical dilution
shall be determined using the CORMIX model using the highest
daily average
discharge rate for the three days prior to the day in which the
test sample is
collected, the discharge pipe diameter, the measured discharge
density, and the
depth difference between the discharge pipe and the sea
bottom.
Input Parameters:
Density Gradient = 0.163 kg/m3/m
Ambient seawater density = 1023.0 kg/m3
Well Treatment wastewater density = 1030.0 1680.0 kg/m3
Completion and workover fluids = 1030.0 1680.0 kg/m3
Current speed = 5 cm/sec (200 m water
depth) Permittees shall retain the model runs as part of the
NPDES records.
Samples for the acute WET tests shall be obtained at the nearest
accessible point
after final treatment and prior to discharge to surface
waters.
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b. Monitoring Requirements
Volume. The highest daily total discharge and the 3-month
average discharge must
be estimated and reported on the DMR in barrels per month.
Well Treatment Completion and Workover Reporting
Requirements.
Operators of leases where well treatment, completion, or
workover fluids are discharged shall
collect and report the information listed below. This
information shall be reported with the
discharged monitoring report for the quarter in which the
discharge is made. If discharges
commence in one quarter and cease in the following quarter,
reporting should be done in the
later quarter.
For each well in which operations are conducted that result in
the discharge of well
treatment, completion, or workover fluids the following shall be
reported with the discharge
monitoring report for the quarter in which the activity is
done:
Lease and block number
API well number
Type of well treatment or workover operation conducted
Date of discharge
Time discharge commenced
Duration of discharge
Volume of well treatment
Volume of completion or workover fluids used
The common names and chemical parameters for all additives to
the fluids
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The volume of each additive
Concentration of all additives in the well treatment
Concentration of all additives in the completion, or workover
fluid
Results of Whole Effluent Toxicity (WET) tests for well
treatment fluids discharged
separately from the produced water discharge. Additional
toxicity testing
requirements are contained in Part V.15.b of this permit.
Information collected for this reporting requirement shall be
submitted as an attachment
to the DMR or in an alternative format requested by the operator
and approved by EPA
Region 4.
Industry-Wide Study Alternative
Alternatively, operators who discharge well treatment completion
and/or workover
fluids may participate in an EPA-approved industry-wide study as
an alternative to
conducting monitoring of the fluids characteristic and reporting
information on the
associated operations. That study would, at a minimum, provide a
characterization of
well treatment, completion, and workover fluids used in a
representative number of
active wells of varying depths (shallow, medium depth and deep
depths). In addition,
an approved industry-wide study would be expected to provide
greater detail on the
characteristics of the resulting discharges, including their
chemical composition and
the variability of the chemical composition and toxicity. The
study area should
include a statistical valid number of samples of wells located
in the Eastern Gulf of
Mexico (GOM) and may include the Western and Central Areas of
the GOM under
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the permitting jurisdiction of EPA Region 6, and operators may
join the study after the
start date. The study plan should also include interim
dates/milestones.
A plan for an industrywide study plan would be required to be
submitted to EPA
Region 4 for approval within six months after the effective date
of this permit. If the
Region approves an equivalent industry-wide well treatment
fluids discharge
monitoring study, the monitoring conducted under that study
shall constitute
compliance with these monitoring requirements for permittees who
participate in such
the industry-wide study. Once approved, the study plan will
become an enforceable
part of this permit. The study must commence within six months
of EPAs approval. If
the Region does not approve the study plan or if a permittee
does not participate in the
study, compliance with all the monitoring requirements for well,
completion, and
workover fluids is required (see above). The final study report
must be submitted no
later than three years from the effective date of this
permit.
c. This discharge shall be considered produced water when
commingled with produced
water.
7. Sanitary Waste (Facilities Continuously Manned for 30 or more
consecutive days by 10
or More Persons)
a. Prohibitions
Solids. There shall be no discharge of floating solids.
Observations must be made
once per day, during daylight in the vicinity of sanitary waste
outfalls, and at the time
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during maximum estimated discharge. The number of days solids
are observed during
the quarter shall be reported on the DMR.
b. Limitations
Total Residual Chlorine. Discharges of sanitary waste must
contain a minimum of
1.0 mg residual chlorine per liter and shall be maintained as
close to this concentration as
possible at all times. A grab sample must be taken once per
month and the minimum and
average concentrations for the monitoring period shall be
reported on the DMR. The
approved analytical methods are Hach CN-66-DPD or the EPA method
specified in 40
C.F.R. Part 136 for Total Residual Chlorine. Samples must be
taken at the nearest
accessible location prior to discharge and after final
treatment.
Exception - Any facility which properly maintains a marine
sanitation device (MSD)
that complies with pollution control standards and regulations
under Section 312 of the
Act shall be deemed in compliance with permit prohibitions and
limitations for sanitary
waste. The MSD shall be tested annually for proper operation and
the test results
maintained at the facility or at an alternative site if not
practicable. The operator shall
indicate use of an MSD on the DMR.
8. Sanitary Waste (Facilities Continuously Manned for 30 or more
consecutive days by 9 or
Fewer Persons or Intermittently by Any Number)
Prohibition. There shall be no discharge of floating solids. An
observation must be
made once per day when the facility is manned, during daylight
in the vicinity of sanitary
waste outfalls, and at a time during maximum estimated
discharge. The number of days
solids are observed shall be reported on the DMR.
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Exception - Any facility which properly maintains an MSD that
complies with
pollution control standards and regulations under Section 312 of
the Act shall be deemed
in compliance with permit prohibitions and limitations for
sanitary waste. The MSD
shall be tested annually for proper operation and the test
results maintained at the facility
or at an alternative site if not practicable. The operator shall
indicate use of an MSD on
the DMR.
9. Domestic Waste
a. Prohibitions
Solids. There shall be no discharge of floating solids.
b. Limitations
Solids. See Part I.C.4 - Rubbish, Trash and Other Refuse.
c. Monitoring Only Requirements
Solids. An observation must be made during daylight in the
vicinity of domestic
waste outfalls and at a time during maximum estimated discharge.
The number of days
solids are observed must be recorded and reported on the
DMR.
10. Miscellaneous Discharges
The following miscellaneous discharges are authorized for
discharge: Desalination Unit
Discharge; Blowout Preventer Control Fluid; Uncontaminated
Ballast Water; Uncontaminated
Bilge Water; Mud, Cuttings, and Cement (including tracers) at
the Seafloor; Uncontaminated
Seawater; Uncontaminated Freshwater; Boiler Blowdown; Source
Water and Sand;
Diatomaceous Earth Filter Media; Subsea Well